Audit Issues

As stated above, we are considering the results of two audit reports in this proceeding. Several of the Energy Division's recommendations point out the need for clarification of some of our decisions. Given the complexity of these issues, this is not surprising, particularly because the determination of certain related issues have been presented in other proceedings. For example, Energy Division makes several recommendations regarding whether the utilities are in compliance with § 367(e)(1) cost allocation and firewall requirements. For the rate freeze period, these issues were addressed in the 1998 Revenue Adjustment Proceeding (RAP) proceeding, and D.99-06-058 determined the appropriate transition cost allocation factors. (D.99-06-058, mimeo. at 42 and 45.) Therefore, we will not address cost allocation issues in this proceeding. Similarly, issues related to transition cost rate group memorandum accounts and the particular contributions of the various rate groups are being considered in A.99-01-016 et al. and will not be considered here.

The Energy Division's review of the TCBA raised important issues related to depreciation or amortization of economic generation for all three utilities. We address these issues first and then describe the accounting issues for each particular utility.

A. Depreciation of Economic Assets

Energy Division requests that the Commission clarify whether the utilities may recover economic generation plant costs in the TCBA. The audit report points out that SDG&E market valued its generation plants at zero and accelerated amortization over the 48-month transition period to recover transition costs. This approach did not comply with the accounting guidelines clarified in D.97-12-039. The fossil assets were ultimately divested for greater than net book value; therefore, the recovery of economic assets occurred through the transition cost balancing account.

Both Edison's fossil and PG&E's fossil and geothermal assets have been divested for greater than net book value, which means that the recovery of economic assets occurred through the TCBA. We must determine whether this approach is lawful, or whether it should be modified now that we have greater experience with the TCBA, market valuation, and our findings related to principles for ending the rate freeze, established in D.99-10-057.

Some history of the TCBA is in order. We established interim TCBAs in D.96-12-077 (70 CPUC2d, 207, 232) and established guidelines for the TCBA in D.97-06-060. These guidelines were discussed and clarified in both D.97-11-074 and D.97-12-039.

Section 367(b) requires a netting of the market valuation process. This means that we must consider the net effect of plants that may be divested or otherwise valued at prices above their net book value or below their net book value. The netting process is fundamental to the final determination of transition costs. In order to implement this requirement, we clarified how accelerated amortization or use of authorized depreciation would occur in D.97-12-039:

The workshop participants discussed various approaches to implementing these requirements. PG&E proposes to estimate the market value of each eligible plant and amortize the difference between net book value and estimated market value over the 48-month transition period. The goal is to adjust book value so that net book value and estimated market value are equivalent. If actual market value exceeds the unamortized book value, PG&E would credit the difference to the TCBA and cease further amortization. If unamortized book value is greater than actual market value, PG&E would recognize this loss as a regulatory asset and amortize this amount over the remainder of the transition period. Most workshop participants agreed that it is more convenient to recalibrate amortization and make revenue requirement changes only upon final market valuation than to do so on a prospective basis.

Edison and SDG&E propose similar approaches, but estimate a market value of zero for generation plants in determining the uneconomic portion of the plant to be amortized over the transition period. We prefer PG&E's approach, which is consistent with the guidelines of D.97-06-060. Edison and SDG&E should estimate a market value for each of their generation plants in determining the uneconomic portion to be amortized over the transition period. PG&E, Edison, and SDG&E should adjust amortization schedules and revenue requirements upon final market valuation, and these changes should be reported in the monthly reports and the annual transition cost proceeding. To make such changes more frequently would be cumbersome and would be unlikely to yield substantially more accurate information. We agree with ORA's observation that any continuation of normal non-accelerated depreciation after formal market valuation does not accrue to the transition cost balancing account, but must be recovered either through market revenues or as part of the hydroelectric or geothermal revenue requirement. (D.97-12-039, mimeo. at 5-6.)

In its response to Energy Division's report, PG&E provides further clarification. PG&E agrees with Energy Division's finding that depreciation, return, and taxes associated with must-run hydro and geothermal plants are not recorded in the TCBA, but in the associated memorandum accounts. This is consistent with our determination that sunk costs for must-run hydro and geothermal plants should be recovered through revenues from the market. (Resolution E-3538, p. 10, Finding 12.) PG&E states that these concepts were authorized in D.97-06-060 and D.97-11-074, more fully fleshed out in Energy Division workshops held in August, 1997 as presented in the September 16, 1997 Workshop Report, and that this approach was clarified in D.97-12-039.

These amortization guidelines require PG&E to amortize the difference between the net book value of each plant and the estimated market value of each plant through the TCBA. In the event that market value is greater than net book value, there are no uneconomic costs to be amortized and normal (or authorized) depreciation is recorded instead and used to develop the sunk cost revenue requirement for that particular plant. When plants undergo final market valuation, that value will be compared to the net book value of each plant to determine the ultimate credit or debit to the TCBA. Thus, PG&E maintains that the Commission authorized the recovery of costs associated with economic plant in the TCBA.

We agree with PG&E's description, but provide further clarification in this decision. Despite our instructions in the various transition cost decisions, it appears that SDG&E has not complied with the required approach for estimating market value. We discuss both the theoretical implications and the pragmatic consequences of rectifying this noncompliance and how this accounting should be performed in the future. As we predicted in D.97-11-074, these issues are complex and we wanted to ensure that any modifications or clarifications could be made early on in the process. "This first proceeding may be somewhat attenuated, but by addressing these issues early, we will be able to implement any required changes to our approach in a timely fashion." (D.97-11-074, mimeo. at 178.)

Because the plants are economic, in theory, SDG&E should recalculate the amortization for plants sold above net book value based on authorized depreciation rates, rather than on the 48-month amortization beginning January 1, 1998. This date assumes that the utilities were aware of market conditions for divestiture of power plants, which is a reasonable assumption. We recognize that market value estimates and economic conditions were favorable to both Edison and PG&E announcements that they would dispose more than 50% of their fossil generation plants prior to that time. Should we require such a recalculation, this figure would reflect the appropriate authorized depreciation and a correction to both the interest calculation on the TCBA balance and the credits to the TCBA upon final market valuation.

As a practical matter, under this approach, the gain on sale to the TCBA when the divestiture transactions close would be less than it would have been had the market value been estimated at zero. Thus, over time, there is no net effect on the TCBA.

PG&E filed its application for the "first wave" of divestiture in November, 1996 (A.96-11-020). Bidders submitted binding offers in November, 1997 and the Commission issued its decision in December of 1997 (D.97-12-107). Similarly, Edison submitted its divestiture application in November of 1996 and a Commission decision was issued in late 1997 (D.97-10-059). Thus, it is reasonable to assume that PG&E and Edison had ample notice that these plants were likely to sell above book value. SDG&E filed its divestiture application in December of 1997 and binding offers were received in December 1998. (D.99-02-073, mimeo. at p. 4.) There was no reason to assume that market value would be below book value. It is both realistic and equitable to deduce that the utilities should have estimated market value greater than book value as of January 1, 1998.

At a minimum, SDG&E should have been following the guidelines proposed by PG&E in the Energy Division workshop and adopted in D.97-12-039. That is, each of the three utilities should have estimated market value such that each plant's market value was equivalent to book value. (Id. at 22, Finding of Fact 3.)

We do not intend to allow ratemaking accounting provisions, established prior to the beginning of the transition period and prior to the Commission's experience with market valuation and divestiture, to preclude us from revising these provisions as necessary to ensure that transition cost ratemaking is consistent with the law. Based on the record⁵ before us, we will revise the approach for accounting for economic assets.

According to the procedures discussed in the Energy Division workshop report and adopted in D.97-12-039, for those plants with estimated market value greater than net book value, no credit is made to the TCBA until the close of sale or the issuance of a Commission decision, if appraised. For those plants that are retained, depreciation recorded on financial books continues, based on Generally Accepted Accounting Principles (GAAP). Recovery of operating costs occurs through the market, i.e., through the memorandum accounts for ratemaking purposes. For those plants sold or appraised below net book value, a regulatory asset is established to amortize the difference between net book value and market value through the TCBA until 2001 or the end of the rate freeze. If the plant is kept, it is written down to its market value for financial reporting purposes and depreciation is based on that new value, based on GAAP.

On a prospective basis, for those assets currently retained, PG&E and Edison shall estimate the market value of each plant asset on an aggregate basis and shall record authorized depreciation in the appropriate memorandum account for those assets with estimated market value greater than net book value. Authorized depreciation through the TCBA will cease at that point. If estimated market valuation results in an amount less than book value, accelerated amortization shall continue until actual market valuation occurs, at which point a recalibration of amortization is appropriate. PG&E, Edison, and SDG&E shall adjust their 1999 ATCP filings accordingly.

We recognize that these are more specific guidelines than had been previously provided; therefore, they will be applied on a prospective basis. In addition, we propose that the utilities should credit the TCBA based upon estimated market value.

On January 10, the assigned Commissioner and ALJ issued a joint ruling providing parties with the opportunity to file supplemental briefs on this issue. Parties in A.96-08-001 et al., A.99-01-016 et al., and A.99-09-053 were also allowed to file briefs and reply briefs on this issue.⁶ Parties in each of these proceedings were also allowed to participate in final oral argument, held on February 14, 2000.

PG&E, Edison, SDG&E, ORA, California Manufacturers Association and California Large Energy Consumers Association (jointly, CMA/CLECA), California Industrial Users (CIU), Enron Corporation (Enron), The Utility Reform Network, Department of General Services, and California Farm Bureau (TURN/DGS/Farm Bureau, jointly), Agricultural Energy Consumers Association (AECA), and Environmental Defense filed supplemental briefs. PG&E, Edison, ORA, and Enron filed reply briefs. PG&E, Edison, SDG&E, ORA, TURN, CMA/CLECA, CIU, and Enron participated in final oral argument.

This change in accounting is consistent with our determinations in D.99-10-057:

AB 1890 established the rate freeze for each utility as a way of permitting the utility an opportunity to recover uneconomic generation costs, or `transition costs,' within a specified period. Briefly, the utility draws down outstanding generation asset costs depending on the revenues remaining after paying off all other authorized costs, such as those associated with the electric distribution system, public policy programs, and transmission costs. The rate freeze ends after the utility has recovered specified generation costs, as set forth in Section 368(a):

These (frozen) rate levels for each customer class...shall remain until the earlier of March 31, 2002, or the date on which the Commission-authorized costs for utility generation-related assets and obligations have been fully recovered.

If specified transition costs are drawn down before the statutory end of the transition period, the Commission must establish a method for determining the date of the end of the rate freeze. (D.99-10-057, mimeo. at pp. 5-6.)

In that decision, we adopted a settlement that requires PG&E and Edison to establish procedures to provide a quarterly forecast that estimates the

date the rate freeze will end and to implement the end of the rate freeze. We also directed PG&E to estimate the market value of its hydro assets, by directing PG&E to provide four estimates of the end of the rate freeze, each assuming a different value for the hydro assets, ranging from the book value of the plant to three times that amount. (Id., p. 8.)

Finally, we discussed the fact that the rate freeze ends, by law, on the date that the utility has recovered relevant transition costs, consistent with §§ 367 and 368. Sections 367(a) and 368(a) do not permit the utilities to carry over after the rate freeze those costs incurred during the rate freeze. Exceptions to the rate freeze that are not specifically enumerated in AB 1890 are not lawful.

Applying these principles consistently means that we must ensure that the TCBA is credited appropriately for estimated market value. Parties raised various threshold issues in their briefs, including whether the Commission should allow the utilities to determine the estimated market value or should assign a market value after hearings. PG&E and Edison state that adopting the estimated market value concept violates specific Pub. Util. Code sections and AB 1890.

PG&E argues that Commission determination of estimated market value would trigger § 216(h). This section provides that generation assets owned by any public utility and subject to rate regulation shall continue to be subject to regulation until those assets have undergone market valuation in accordance with Commission-established procedures. TURN argues that PG&E's contention ignores the fact that the Commission must determine and establish procedures for market valuation. We agree with TURN. AB 1890 did not modify § 851 requirements that a public utility cannot sell, lease, assign, mortgage, or otherwise dispose of any property necessary or useful in the performance of its duties to the public without first having secured an order authorizing it to do so from this Commission. TURN also points out that § 367(b)'s provision that market valuation be final occurs at the time those assets are exposed to market risk, which would not be the case with crediting the TCBA for estimated market value.

Edison and PG&E contend that because these issues were not identified in the Scoping Memo issued in this proceeding, adopting this proposal would violate § 1701.1(b). These parties contend that due process requires that parties have the opportunity to review and contest the proposal, prepare testimony and cross examine witnesses so the Commission has "the benefit of a full evidentiary record before modifying a prior Commission decision."

According to Edison and PG&E, anything less denies the utilities their right to evaluate and provide input on a proposal that could significantly affect their interests (D.97-05-091, mimeo. at p. 5-6.) PG&E, in particular, states that fundamental to the constitutional right of due process is the right of notice and an opportunity to be heard in a timely and meaningful manner (Mathews v. Eldridge, 424 U.S. 319, 333 (1976).) PG&E and Edison state that § 1708 requires both notice and opportunity to be heard "as provided in the case of complaints," which means that an oral hearing must be granted if requested. They therefore request a separate evidentiary phase of this proceeding, or that this proposal be deleted from the final decision.

These accounting changes can be accomplished without hearings. Parties have had the opportunity to be heard in supplemental briefs, reply briefs, and final oral argument. Furthermore, the Scoping Memo issued in this proceeding by Commissioners Duque and Conlon on December 16, 1998 stated that:

ORA requests that the scope be expanded to consider issues related to the mechanics of the TCBA entries and the guidelines established by the Commission. ORA requests clarification related to the use of excess headroom to accelerate transition cost recovery, insufficient headroom to cover scheduled amortization, revenue credits on a plant-specific basis, and delays in making the appropriate revenue credits. These issues are appropriate to consider in this proceeding. .

The Scoping Memo also stated that the proceeding would adjust accelerated depreciation and account for results of divestiture proceedings in the TCBA, would review the order of acceleration and application of revenues, and would clarify how guidelines would be applied regarding the issues raised by ORA.

We agree with TURN/DGS/Farm Bureau, who maintain that revising the accounting guidelines in this fashion will serve to achieve an outcome more consistent with Sec. 330(t), which requires an orderly transition that provides the utility with a fair opportunity to fully recover its uneconomic costs while achieving the transition as expeditiously as possible. ORA, TURN/DGS/Farm Bureau and CMA/CLECA dispute the contention that these accounting changes necessarily constitutes "market valuation" and explain that the utilities cannot argue that estimated market valuation equal to either zero or net book value is acceptable, but that an estimated market value greater than net book value is not.

TURN explains that § 701 provides further support for concluding that the Commission's ratemaking authority includes the ability to devise and rely upon estimated market value to calculate the amount of uneconomic assets eligible for recovery and the end of the rate freeze. This section grants the Commission the power to "do all things, whether specifically designated in this part or in addition thereto, which are necessary and convenient" in the exercise of its powers to supervise and regulate public utilities. TURN also likens this approach to granting interim rate relief, which was upheld in TURN v. PG&E (1988) 44 Cal.3d 870, 750 P.2d 787, 788. The Court affirmed that where the agency is vested with the power to grant a particular relief, that power carries with it all of the incidental, necessary and reasonable authority to grant that which is less. TURN explains that the Court focused particularly on the Commission's balancing of various competing interests and contends that the same logic applies in this situation.

ORA argues that $2 billion is a sufficiently conservative amount for these purposes and that these actions should be undertaken in A.99-09-053, the proceeding to market value PG&E's hydro assets. Environmental Defense maintains that the schedule in the hydro proceeding is too expedited to allow this issue to be fully developed and could not address these accounting changes until June, 2001. Other parties (AECA, Enron) don't trust the utilities to come up with an amount that is not woefully conservative. Enron also contends that hydroelectric power purchase agreements should be included, because these are economic generation assets. Enron suggests expedited hearings, as does CIU and CMA/CLECA.

We will modify the accounting for generation assets in this proceeding. As stated in the Scoping Memo, such accounting changes are one of the purposes of the ATCP. We agree with the utilities that hearings on these issues are likely to be contentious and lengthy. At the final oral argument, parties requested guidance on the determination of a "conservative" amount to be recorded for these purposes. We find that, at a minimum, PG&E and Edison should credit their respective TCBAs for the aggregate net book value of the non-nuclear assets, including the land surrounding such assets and the Helms pumped storage plant. Assets jointly owned with other utilities should be excluded from this approach. We strongly encourage the utilities to realistically assess the estimated market value for those plants expected to be valued at greater than net book value. These credits should be reflected in the monthly TCBA reports and the annual report. PG&E and Edison should include a list of assets with net book value over $500,000 in the first TCBA report in which these changes are made.

The proposed decision called for the establishment of a new account, the Estimated Gain on Asset Disposition Account. PG&E and Edison are convinced that allowing a true-up when estimated market value is greater than actual market value will violate § 368(a) and the principles established in D.99-10-057. We are persuaded that crediting the TCBA for the aggregate net book value of the remaining generation non-nuclear assets is an extremely conservative approach and remedies these concerns. D.99-10-057 established ratepayer refund accounts for overcollections that occur when CTC collection extends beyond the point when generation-related transition costs are recovered. Accordingly, we do not establish this new account.

PG&E argues that establishing the Estimated Gain on Asset Disposition Account would establish a generation-related regulatory asset that, in turn, must be recovered prior to the end of the rate freeze. PG&E argues that absent a legally sustainable true-up, PG&E would have to take an immediate write-off against earnings as a result of the assigned estimated value. PG&E further contends that such a result would lead to a "loss of the opportunity to collect these uneconomic costs through CTC during the transition period and would violate Sections 330(s) and (t), as well as the Taking Clause of the United States and California Constitutions."

We do not agree with PG&E's analysis, but in any event, PG&E's arguments are moot, because we are not establishing the Estimated Gain on Asset Disposition Account. The Commission has the discretion to manage such balancing accounts such as the TCBA in a manner that avoids huge over-collections or under-collections of revenues, consistent with the guidelines established in D.97-06-060 and clarified in D.97-11-074 and D.97-12-039. Crediting the TCBA for the aggregate net book value of remaining non-nuclear generating assets is a simple accounting procedure that manages the netting procedure called for in § 367(b) during the transition period, rather than waiting for the conclusion of the transition period.

Edison contends that granting Energy Division's recommendation would result in a "confiscatory outcome" because Edison would have no opportunity to recover its investment or earn a return on that investment after December 31, 1997. Edison contends that it is entitled to the opportunity to recover all costs associated with its fossil generating stations through March 31, 1998 and explains that prior to January 1, 1998, Edison recovered depreciation, return, and taxes associated with these assets through its ERAM rates. Edison maintains that by establishing the ISO/PX Implementation Delay Memorandum Account (IPIDMA) to capture all costs that would not be recovered through the TCBA, the Commission maintain the "regulatory status quo" during the period before the new markets were functioning. In essence, Edison contends that the concept of cost recovery for this period should mirror what was already in effect on December 31, 1997.

Edison disputes the fact that Energy Division categorizes those plants sold at a gain as "economic." Edison states that the gains realized on these plants reflect the results of auctions to buyers who determined a value based on the probability of selling electricity into the PX or other markets over the long term and contends that this is different from the value of those plants owned by Edison between April 1, 1998 and the sales date. Edison recognizes that over an entire year or longer period, these plants may prove to be economic, but contends that during this time period, these plants were not economic in that "total costs of these facilities could not be recovered through market prices." (Exhibit 13, p. 22.)

We are not persuaded by Edison. As we discussed above, in D.97-12-039, the Commission required the utilities to estimate the fair market value of its plants, rather than assuming that the market value was equal to zero. Furthermore, § 367(b) requires that the Commission determine which transition costs are reasonable and requires a netting approach. There is no confiscatory taking to this accounting approach. Edison is allowed authorized depreciation through the TCBA. On a prospective basis, authorized depreciation, taxes, and return will be recovered through market revenues in the must-run and non-must-run memorandum accounts.

B. SDG&E

For SDG&E, the Mitchell-Titus audit report determined that balances in the ECAC, ERAM, and the Interim TCBA were transferred appropriately. Mitchell-Titus also concluded that balances in the San Onofre Generating Stations (SONGS) 2 & 3 Sunk Cost Memorandum Account are reasonable and were properly closed to the TCBA. Finally, the audit report concluded that headroom revenues were calculated in accordance with the Commission-approved procedures delineated in SDG&E's preliminary statements and that no material misstatements of the CTC residual revenue were identified.

Mitchell-Titus made three major recommendations for SDG&E's accounting procedures. First, Mitchell & Titus recommends that SDG&E develop formal accounting procedures to document the sources and uses of data and data flow needed for the TCBA and other electric restructuring-related accounts. SDG&E explains that it does not generally develop particular accounting practices for processes that are in transition, particularly since its rate freeze has ended (See D.99-05-051).

We recognize that SDG&E will be developing new accounting procedures related to the end of the rate freeze. It is important, however, that the Commission have a full understanding of the reasonableness of the TCBA entries. Therefore, SDG&E should work closely with the Energy Division to ensure that our staff has access to all necessary data and information to understand the flow of data related to the review of the next record period, July 1, 1998 - June 30, 1999.

Second, Mitchell-Titus recommends that SDG&E adjust its CTC Residual Revenue for the settlement of its transmission revenue requirement approved by the Federal Energy Regulatory Commission (FERC) and review its proposed accounting for transmission revenue. In Resolution E-3577 (April 22, 1999), we have approved SDG&E's accounting for crediting transmission rate subject to refund to the TCBA.

Third, Mitchell-Titus recommends that SDG&E file an advice letter confirming that it has made the refunds needed because of the withdrawal of the Fuel Price Index Mechanism (FPIM) rate adjustment billed in June, 1998. On February 1, 1999, SDG&E filed Advice Letter 1149-E which contains a proposed refund plan associated with the FPIM. We approved this advice letter by Resolution E-3603 (July 8, 1999).

The Energy Division's audit report presented several findings for SDG&E. Energy Division recommends that carrying costs on SDG&E's Portland General Electric/AMAX Coal Company Contract (PGE/AMAX) regulatory asset be removed from SDG&E's purchased power costs. Energy Division made this recommendation because our staff could not find the proper authorization for including these costs in the TCBA. SDG&E is entitled to the recovery of the difference between actual payments under eligible purchase power contracts and the cost of comparable energy purchases from the Power Exchange. (§ 367; D.97-11-074, mimeo. at p. 204.) We agree that the PGE/AMAX contract is eligible for transition cost recovery.

SDG&E points out that in D.96-06-033, the Commission approved a settlement agreement that provided that carrying costs are an integral part of the total recoverable costs through these contracts. We have reviewed the underlying decisions and agree with our staff that carrying costs should not continue to be accrued as transition costs. For purchase power contracts, transition costs are the difference in the actual payments made to Portland/AMAX and the corresponding revenues from the Power Exchange, ISO, or other markets for comparable energy. The TCBA allows interest (calculated at the three-month commercial paper rate) to accrue on both under-and overcollections. It is not equitable to continue to allow both carrying costs and an assessment of interest to accrue in the TCBA. We cannot allow this double recovery. Therefore, SDG&E should adjust its TCBA appropriately. Carrying costs may accrue on these contracts up to the point of transfer to the TCBA.

Energy Division also recommends that SDG&E's Embedded Cost of Debt subaccount be removed from recovery through the TCBA. D.97-11-074 requires SDG&E to make a showing to ensure that the savings in the embedded cost of debt are deducted from SDG&E's costs. Instead of removing its highest cost debt in calculating its embedded cost of debt, Energy Division points out that SDG&E removed its lowest cost debt and added the increased debt costs to its TCBA. The report recommends that the increased cost be disallowed.

In response, SDG&E states that its rate reduction bond (RRB) application (A.97-05-022) anticipated general changes to its cost of capital because the Market Indexed Capital Adjustment Mechanism (MICAM) under which SDG&E currently operates will not expire until December 31, 2000. In addition, its actual capital structure cannot be updated before the minimum target change in utility A bond rates is exceeded. Therefore, in the RRB application SDG&E proposed a change to its embedded cost of debt and to pass the impact of the change to all of its customers through charges to the TCBA.

SDG&E asked that the outstanding tax-exempt industrial development bonds (IDB) be preserved for ratemaking purposes. SDG&E achieved this by removing the lower cost IDBs from the embedded cost of debt calculation; however, they were not physically retired. To offset the amount of IDBs removed for ratemaking purposes, an equal amount of the RRB proceeds was invested at short- to intermediate-term rates to offset the variable interest rate paid to the holders of IDB. SDG&E did not want to retire the IDBs with the RRB proceeds because SDG&E did not want to be at risk for issuing taxable debt higher than the cost of the RRBs. Also, SDG&E points out that the IDBs could prove difficult to obtain. D.97-09-057 approved the proposal.

Upon receiving the Commission's approval, SDG&E states that it revised its embedded cost of debt, determined a new overall rate of return, and calculated the resulting change in revenue requirement. The change was amortized into the TCBA monthly. A total of $1.3 million was charged to the TCBA between January and June 1998. SDG&E discontinued the charge after D.99-06-057, the unbundling cost of capital decision, was issued.

SDG&E indicates that it removed $80 million of variable-rate IDBs along with the related interest expense from its embedded cost of debt calculation. In the future, it plans to draw down the equivalent investments when funds are needed for future utility-related improvements. At that time, the IDBs will be brought back to the ratemaking capital structure. SDG&E believes it has pursued a capital structure reduction which followed the authorized capital structure proportions and kept the ratio of low cost variable rate debt within rating agency and SDG&E corporate targets and concludes that the entries to the TCBA are appropriate.

We approved SDG&E's proposal in A.97-05-022 as stated in the text of D.97-09-057. SDG&E's entries to the TCBA are appropriate. SDG&E should, however, track the interest income on the investments against the interest expense on the IDBs and credit the positive difference to the TCBA until the IDBs are brought back to the capital structure for ratemaking purposes. SDG&E shall show this entry separately in its monthly TCBA report under CTC Revenue Account beginning January 1, 2000.

Energy Division states that the Commission must determine whether the utilities may recover their nuclear material and supply costs in the TCBA. SDG&E declares that Sections 367(a)(4) and 368(d) incorporate by reference D.96-01-011 and D.96-04-059, in which the Commission authorized SDG&E to accelerate the recovery of SONGS sunk costs. A portion of these sunk costs represent material and supply inventory. We have reviewed the underlying decisions and agree that nuclear material and supply inventory is eligible for recovery as transition costs.

Finally, the Energy Division adjusted SDG&E's Unrecognized PBOP Regulatory Asset to reflect the December 31, 1997 estimate. SDG&E has accepted this adjustment.

C. Edison

Mitchell-Titus determined that, in general, the balances in the various balancing accounts were transferred to the ITCBA properly. Mitchell-Titus makes four significant recommendations for Edison:

1. Edison should develop formal accounting procedures to document the sources and uses of data and data flow needed for maintenance of the TCBA, TRA, and other accounts related to industry restructuring.

2. Edison should emphasize that the reporting of revenues is an integrated process that crosses organizational boundaries and requires the interface of several systems and the effective communication among several groups.

3. Edison should rerun January through June numbers to restate the bundled components of revenue and headroom revenues when all discrepancies and known system defects have been corrected, and should reconcile total revenue and headroom revenue recorded in the TRA and shown in the special purpose financial statements as of June 30, 1998. Edison should be prepared to justify and document all corrected amounts.

4. Edison should file an advice letter demonstrating that the minimum charge billing defect has been corrected and that appropriate billing adjustments have been made.

Edison states that the "audit validated SCE's calculation of headroom revenues and balance transfers to the TCBA during the audit period," and intends to implement most of the audit report's findings and conclusions. Edison was in the process of implementing integrated process development and process system test strategies that address several of the issues identified in the audit report and plans an internal audit during 1999 to test the accuracy and interface between the new billing and revenue reporting systems. Edison should present an updated report on these systems in the 1999 ATCP and should work with Energy Division to ensure that our staff approves of and understands all such billing and accounting system changes.

Edison disagrees with the recommendation to develop formal accounting procedures related to the TCBA, TRA, and other related accounts, since it believes these procedures were carefully worked out by various parties to industry restructuring proceedings and entailed extensive discussion, compromise, and consensus. As we determined for SDG&E, we will not adopt a recommendation for formal accounting procedures, but will require Edison to work closely with our staff to ensure that all such procedures are transparent and understandable, although complex.

Edison does not agree that an advice letter is needed to correct the minimum charge billing defect, although it agrees that such defects have occurred. Edison states that it has already made the corrections and is in the process of reviewing and correcting the historical impact on affected accounts. Again, we will require an updated accounting for these defects in the 1999 ATCP.

Energy Division raised certain audit issues with respect to Edison, some of which are identical to those raised for SDG&E and PG&E. To the extent that issues are common to all three utilities, we resolve them in the same manner. We address additional issues in dispute here.

Energy Division recommends that Edison should revise its CPUC jurisdictional factors to reflect those adopted in D.96-01-011, noting that Edison, in fact, made this adjustment. However, Edison states that it disagrees that these are the correct jurisdictional factors to use. Edison states that Resolution E-3538 authorized Edison to create the Jurisdictional Allocation Memorandum Account, effective April 1, 1998. The purpose of this account is to record the difference between generation-related revenues and costs using Edison's actual jurisdictional allocation factors, based on recorded sales and Commission-authorized allocation factors from D.96-01-011. The correct jurisdictional allocation factors will be resolved in Edison's 1999 RAP application, A.99-08-022 et al. We agree with this approach and will not adopt Energy Division's recommendation at this time.

Energy Division also states that Edison is not complying with Guideline 3 as stated in D.97-06-060 and clarified in D.97-12-039, which requires that any additional revenues be applied to first accelerate the depreciation of those transition cost assets with the highest rate of return and in a manner which provides the greatest tax benefits.

Edison recognizes that the overcollected balance in its TCBA was $350.7 million, but explains that this occurred because of the net gain on divestiture of its fossil plants and the amounts removed from the TCBA that were initially transferred from the IPIDMA to the TCBA and instead were considered in Edison's ECAC proceeding. Had the IPIDMA balance been approved for recovery during the record period in question, Edison's overcollected balance would have equaled $112 million. Furthermore, Edison believes that had the full year been included in this record period, the data would have shown Edison's overcollected balance decreasing rapidly after June 30, 1998. In addition, Edison believes we must consider Guideline 8, which requires the utilities to manage the acceleration of assets to avoid major under- or overcollections of transition costs. Finally, Edison contends that it had to consider the recovery of its electric industry restructuring costs in determining whether to accelerate its generation-related assets. Edison applied for recovery of these costs in A.98-05-015 and proposed to recover these costs through its Transition Revenue Account (TRA). Edison explains that had these costs been authorized for recovery through the TRA during the record period, the residually-calculated CTC revenue would have been reduced, and thus, the credits to the TCBA would have been decreased. Edison believes its approach is consistent with Guideline 8.

It is worth repeating our guidelines, as clarified in D.97-12-039:

1. The recovery of certain costs that are currently incurred may be deferred. The recovery of employee transition costs (as addressed in § 375) may be deferred to the post-2001 period and recovered through December 31, 2006. [Footnote omitted.] Section 376 provides that, to the extent that Federal Energy Regulatory Commission (FERC) or Commission-approved recovery of the costs of utility-funded programs to accommodate implementation of direct access, the Power Exchange, and the ISO, reduces the ability of the utilities to collect generation-related transition costs, those generation-related costs may be collected after December 31, 2001, in an amount equal to the implementation costs that are not recovered from the Power Exchange or ISO. Generation-related transition costs which may be displaced by the collection of renewable program funding (as addressed in § 381(d)) may be collected through March 31, 2002. Other than these exceptions, current costs should be recovered as incurred, as required by ratemaking principles and the accounting principle of matching revenues and expenses.

2. Current costs are those cost items eligible for transition cost recovery that are incurred in the current period. The definition of current costs also includes the amortization of depreciable assets on a straight-line basis over the 48-month transition period. In addition, certain regulatory assets which may be jeopardized by write-offs should be amortized ratably over a 48-month period. The specific regulatory assets to which this guideline applies should be determined once Phase 2 eligibility criteria are resolved. The amortization of the investment-related assets should include a provision for associated deferred taxes and the reduced rate of return called for in the Preferred Policy Decision (D.95-12-063, as modified by D.96-01-009) [Footnote omitted.] To accommodate ongoing market valuations and accelerated recovery, the utilities should recalibrate recovery levels for remaining months of the schedule, if necessary. To the extent that revenues do not cover costs in a current period, revenues should be applied first to costs incurred during that period and then to scheduled amortization, including that of regulatory assets.

3. To the extent that any additional headroom revenues remain and until such time as plants are depreciated to their anticipated market value, any additional revenues should be applied first to accelerate the depreciation of those transition cost assets with a high rate of return and in a manner which provides the greatest tax benefits. In this way, accelerated recovery of transition costs will benefit shareholders and ratepayers.

4. As assets that are currently included in rate base are amortized, rate base should be reduced correspondingly on a dollar-for-dollar basis, including the impact of associated taxes. This will ensure that the utilities are in compliance with § 368(a), which requires among other things that transition costs be amortized such that the rate of return on uneconomic assets does not exceed the authorized rate of return.

5. As a general guideline for those assets subject to market valuation, generation-related assets should be written down to their estimated market value, but not below, based on a relatively broad estimate of market value. We will be somewhat flexible in applying this guideline. We recognize both PG&E's and Edison's concerns that public disclosure of such estimates could adversely affect the auction process and will address the need for protective orders and confidentiality as the need arises. It is not our intent to revisit the market valuation process occurring in other proceedings.

6. It is the duty of the Commission to determine what transition costs are reasonable and because such costs cannot be determined to be uneconomic or not until we have more information, we reject the utilities' request for complete flexibility in managing their transition cost recovery. We require monthly and annual reports and will institute an annual transition cost proceeding, separate from the Revenue Adjustment Proceeding. In D.96-12-088, we provided that authorized revenues would be established in the respective proceedings for various issue areas and would be consolidated in the Revenue Adjustment Proceeding. In addition, to provide further clarity to this concept, we will require the utilities to revise their pro forma tariffs to indicate that the cost accounts and subaccounts they establish are not labeled as transition cost subaccounts, but are merely the sunk cost accounts and subaccounts. This is important because we are establishing the sunk costs in Phase 2 of these proceedings, but the uneconomic portion of these costs (which is the portion eligible for transition cost recovery) must be established on an ongoing basis.

7. To the extent feasible, current costs, including those categories that may be deferred, should be recovered before December 31, 2001. We expect that the deferred transition costs should be small relative to the transition costs incurred from qualifying facility (QF) contracts and amortizing nuclear assets. Restructuring implementation costs and employee-related transition costs may be deferred with interest at the usual 90-day commercial paper rate. Generation-related transition costs that are deferred because of funding the programs addressed in § 381(d) shall not accrue interest.

8. To the extent possible, the utilities should manage acceleration of assets to achieve a matching of revenues to current costs plus the portion of noncurrent costs that is accelerated, in a manner to avoid major under- or overcollections of the competition transition charge (CTC). To the extent that noncurrent costs are accelerated, the utilities should recalibrate the remaining months of the recovery schedule to adjust the depreciation schedule through the end of the transition period. To the extent that over- or undercollections occur, interest will accrue at the usual 90-day commercial paper rate, with the exception of deferred generation-related transition costs displaced because of funding the § 381(d) programs. (Id. at pp. 3-5.)

The TCBA is an account that requires monthly entries and monthly determinations of transition cost recovery.⁷ For this reason, we require the utilities to submit both monthly and annual reports on the entries made to the TCBA. As we stated in D.97-06-060, the purpose of applying additional revenues to further accelerate those transition cost assets with the highest rate of return is to maximize the interests of both ratepayers and shareholders by ensuring that the greatest amount of revenues is available to collect transition costs, rather than being applied to interest and carrying costs (D.97-06-060, mimeo. at 83, Finding of Fact 6). Ratepayers benefit because the rate freeze may end before December 31, 2001, if transition costs are collected as expeditiously as possible. Similarly, shareholders benefit because there is a greater likelihood of full recovery of transition costs. (Id., Findings of Fact 7 and 8.)

In this case, however, we are reviewing an attenuated record period and must recognize the associated overcollection would be absorbed by a subsequent undercollection. Therefore, we approve Edison's approach for this record period only.

When Edison sold its gas-fired generating stations, the new owners did not purchase all of Edison's generation assets. Energy Division recommends that certain assets, such as fuel oil tanks and associated land, telecommunications facilities, training equipment, Steam Division's chemical facilities, mechanical service shop equipment, Steam Division's central warehouse equipment, and other land, do not qualify as generation-related assets, and that the net gain in value should be determined in this proceeding. Edison contends that these assets are either stranded assets or are currently being used by Edison. At any rate, Edison maintains that these assets are generation-related sunk capital costs, not O&M going forward costs.

We agree with Edison that the fuel oil tanks and associated land should be included in the TCBA, since Edison is holding these assets until the ISO makes a final determination regarding their need for reliability purposes. (See D.97-11-074, mimeo. at p. 72 and D.99-06-078.) Edison explains that certain telecommunications equipment necessary for the operation and maintenance of plants is now being deployed for transmission and distribution functions. Therefore, these are not stranded assets and should not be recovered through the TCBA. Edison has agreed to remove these costs from the TCBA, retroactive to the dates of sales. Edison contends that the other assets should be included in the TCBA.

Such assets are analogous to common and general plant. For on-site assets, the Commission determined that "we will true-up the transition cost balancing account once market valuation occurs and will review any assets not acquired by buyers to determine whether they remain eligible for transition cost treatment." (Id., p. 93.) For off-site assets, we determined that such costs should be excluded from transition cost recovery because we expected that most items would be usable in various other areas of the utilities' or their affiliates' functions:

To the extent these off-site common and general plant costs cannot be fully mitigated, the uneconomic costs of off-site generation-related common and general plant may be recoverable through transition cost treatment. However, we put the utilities on notice that such mitigation efforts will be thoroughly reviewed and scrutinized in the annual transition cost proceedings and that we expect the utilities to use their best efforts to find alternative uses for these assets. (Id., pp. 93-94.)

To the extent that the training equipment, Steam Division's chemical facilities, mechanical service shop equipment, Steam Division's central warehouse equipment are stranded or being used to service Edison's remaining generation facilities, they should be recovered through the TCBA. To the extent these assets are used to "support other activities required under AB 1890," (Exhibit 13, p. 25), Edison has not demonstrated that such assets are either generation-related or that it has used its best efforts to find alternative uses. Therefore, recovery through the TCBA is denied and Edison should make the appropriate adjustments. Issues regarding the "buffer" land that Edison did not sell at its various generation sites were considered in D.99-06-078.

Finally, the Energy Division adjusted Edison's pension transition benefit obligation to reflect a correction to an actuarially-determined value. Edison agrees with this adjustment. Energy Division has also recalculated Edison's generation-related pension, long-term disability, and unrecognized PBOP amounts using an allocation factor of 23.4 percent rather than the 24 percent used by Edison. Edison agrees with this adjustment.

D. PG&E

The Mitchell-Titus audit concluded that headroom revenue determined through the TRA and recorded in the TCBA was properly computed and derived for the record period. In addition, Mitchell-Titus concluded that balances in the balancing accounts and memorandum accounts as of December 31, 1997 were properly transferred to the TCBA. Mitchell-Titus did, however, offer three recommendations for improving PG&E's accounting procedures, all of which PG&E rejects.

First, Mitchell-Titus recommends that PG&E should develop formal accounting procedures to document the sources and uses of data and data flow needed for the maintenance of the TCBA, TRA, and other electric restructuring-related accounts. PG&E believes that compliance with Commission accounting guidance and its own general ledger journal entry policies and procedures ensure that all accounting transactions are properly reviewed and supported.

We direct our Energy Division to discuss these accounting procedures with PG&E and to determine if changes should be made to the monthly and annual TCBA reports. We want to be sure that our staff thoroughly understands PG&E's accounting procedures and, just as important, that the TCBA reports are accessible and easily understood.

Second, Mitchell-Titus recommends that PG&E review its accounting procedures related to the TRA and RRB regulatory asset accounts to determine if it is necessary to record unbilled revenue entries and reversal at a relatively high level of detail. PG&E believes its approach is reasonable, since the use of unbilled revenue does not add significant complexity to the accounts and ensures consistency between ratemaking, financial reporting, and tax accounting. We agree with PG&E and will not adopt this recommendation.

Finally, Mitchell-Titus recommends that PG&E's use of the RRB Memorandum Account be reviewed in comparison to procedures adopted by Edison and SDG&E and that PG&E determine whether this accounting could be simplified. PG&E believes its procedures are not significantly more complex than those used by Edison or SDG&E. Edison does not include unbilled revenues in the calculations, while PG&E does, and PG&E records interest earning accrued to customers after collection, but before payments are made to the bondholders in the RRB memorandum account. PG&E earns interest on FTA funds collected from customers before payment is made to the bondholders and also earns interest from funds held for overcollateralization (to the extent they are not needed to make payments to the bondholders).

PG&E explains that it offsets this interest in the RRBMA with a recorded regulatory liability such that the income does not flow to shareholders, since allowing these amounts to be recorded as income would not reflect the true accounting consequences of the transaction. Finally, PG&E has created a RRB regulatory asset to reflect the benefits the customers have received from the RRB financing. By taking the difference between the outstanding proceeds (net of unrecovered issuance expenses), and the RRB regulatory asset, the amount of oversizing credit can be calculated at the end of the rate freeze. We are not greatly concerned by PG&E's approach, but will carefully review its procedures at the end of the rate freeze to determine that the oversizing credit is properly calculated. If our Energy Division staff finds it necessary to review the accounting procedures before the end of the rate freeze, they should do so.

The Energy Division has developed several recommendations as a result of its review of PG&E's TCBA for the record period. We discuss only those issues to be considered in this proceeding and only those recommendations with which PG&E disagrees.

Energy Division removed PG&E's recorded Diablo Canyon audit costs ($189,229) from the TCBA, which Energy Division believes were recorded without authorization. PG&E explains that this audit was ordered in D.97-05-088, which directed that these costs be part of the revenue requirement (Ordering Paragraph 14(c)). This amount should be included in the TCBA for the 1999 record period. PG&E demonstrates that the components of the Diablo Canyon revenue requirement are recovered through the TCBA and that this recovery mechanism is reasonable for the audit costs. However, these costs were included in Advice Letter 1733-E detailing the 1997 year-end balances of memorandum and balancing accounts to be transferred to the TCBA and the advice letter was not approved until November 15, 1999. The amount amortized through the TCBA should exclude the additional cost for work performed by the independent auditors that PG&E agreed to pay for after the auditors issued a qualified opinion on the Diablo Canyon audit.

We agree with PG&E that the Diablo Canyon costs should be recorded using the annual revenue requirement and the Commission-approved tariff providing for a monthly entry to the TCBA equal to one-twelfth of the annual revenue requirement.

Energy Division notes that PG&E is amortizing or depreciating its December 31, 1995 fossil sunk costs net of its December 31, 1995 depreciation reserve in the TCBA, while Edison and SDG&E used the 1995 sunk costs net of the 1997 depreciation reserve. PG&E explains that this approach is consistent with D.97-11-074 and adjusted the plant and depreciation reserve balances to reflect plant additions and depreciation accruals recorded in 1996, as approved in D.98-05-059. When a decision is issued in A.98-07-058 (which requests recovery for capital additions in 1997 and the first quarter of 1998), PG&E states that it will make further adjustments to net book value. This approach is consistent with our decisions and Energy Division does not take exception as long as such adjustments are appropriately recorded. D.99-10-045 was issued in A.98-07-058 on October 21, 1999; therefore, PG&E should adjust its 1999 ATCP filing accordingly.

PG&E agrees with Energy Division's recommendation to modify its QF costs in the TCBA if any of its QF contracts are not approved by the Commission. In addition, the Energy Division notes that PG&E records its QF shareholder incentives in the QF Shareholder Savings subaccount (QFSSS) based on estimates when the contracts are signed and stated that it was not clear that this is authorized. We agree with PG&E that, in fact, this approach is consistent with D.99-02-085, where the Commission confirmed that shareholders receive the benefit of the 10% shareholder incentive at the time the contract is signed, subject to a true-up when the Commission acts on the application to approve the restructured contract. However, we expect PG&E to comply with D.99-06-089 and to reverse all entries in connection with the $2.47 million in estimated shareholder savings disallowed by D.99-06-089. This true-up should be reviewed in the appropriate ATCP proceeding.

Energy Division removed $112,838 as an adjustment to this account. PG&E disagrees with this adjustment, but agrees that $7,708 should be removed and made that adjustment. We note that a portion of the $112,838 is related to the Mt. Poso restructuring application (A.98-10-030), which was withdrawn at parties' request in D.99-12-088. We will review PG&E's future ATCP filings to ensure that this adjustment was made properly. We agree with PG&E that the 10% shareholder incentive should be applied without including a jurisdictional factor.

The Energy Division believes that PG&E amortized its QF Buyout Regulatory Asset in the TCBA before this was authorized. In D.97-11-074, we stated that the QF Regulatory Buyout Asset amounts for costs incurred prior to December 31, 1995 should be tracked in a memorandum account and transferred to the transition cost balancing account upon our determination of reasonableness. (D.97-11-074, mimeo. at p. 167, Finding of Fact 125, p. 200.) When we issue a decision approving these costs, PG&E may record the regulatory asset in the TCBA and amortize the amounts ratably over the time remaining until the end of the transition period. We recognize that the Commission authorized the utilities to amortize regulatory assets ratably over the 48-month transition period and that there are pending reasonableness review issues in A.95-04-002. PG&E should record the balance for this account in the TCBA which will be trued-up to reflect final decisions in A.95-04-002. No adjustments are needed for the Midsun restructuring addressed in the decision in A.98-04-003.

PG&E also disagrees with the Energy Division's recommendation to remove $140,508 from the TCBA related to the amortization expense of the Angels/Utica Regulatory Asset. PG&E explains that the Commission authorized this regulatory asset in D.96-06-061, which adopted a settlement. The regulatory asset was to be amortized from 1996 to 2000. In D.97-11-074, the Commission authorized recovery of generation-related regulatory assets and obligations authorized for collection in rates as of December 20, 1995, consistent with § 367. We agree with PG&E; this regulatory asset is eligible for accelerated amortization ratably over the 48-month period. However, the unamortized balance should not continue to earn the interest rate adopted in the settlement. This would lead to double recovery of carrying costs, because the TCBA earns the three-month commercial paper rate, as we discuss in more detail below. Once regulatory assets are transferred to an account for recovery, carrying costs should cease to accrue. PG&E should adjust its 1999 ATCP filing accordingly.

Energy Division adjusted the January 1998 balance of PG&E's Western Area Power Administration (WAPA) Regulatory Asset to the December 31, 1996 balance approved by the Federal Energy Regulatory Commission (FERC) in May 1998. PG&E does not disagree with this adjustment but proposes to use the December 31, 1997 balance recently approved by FERC as a basis for amortizing the WAPA regulatory asset. In February 1999, FERC accepted the December 31, 1997 balance of $122,2427.073.49 in Docket No. ER99-1278-000, which results in a monthly amortization of $2,550,564. It is reasonable for PG&E to use this balance rather than the previously approved balance of $142.7 million, which resulted in a monthly amortization of $3,174,291. PG&E should adjust the WAPA amortization prospectively to avoid any double recovery or overlapping entries in the TCBA. No interest should be earned on the unamortized balance, as the TCBA itself earns a return.

Energy Division also recommends that monthly amortization charges related to the Humboldt Regulatory Asset Special Assessment Amortization, the Helms Regulatory Asset Amortization, and the Helms Adjustment Account Amortization should be removed. PG&E states that each of these regulatory assets were addressed in the Mitchell-Titus audit report specifically adopted in D.97-11-074.

We agree with PG&E and will allow amortization of these regulatory assets, consistent with D.97-11-074 and § 367. However, the unamortized balance on these assets should not continue to earn a return, because the TCBA earns the three-month commercial paper interest rate. PG&E should adjust its 1999 ATCP filing accordingly.

Energy Division states that it was unable to document authorization granting PG&E specific authority to record the generation-related portion of the Hazardous Substance Mechanism (HSM) and recommends that amortization and return be disallowed. Energy Division also states that a jurisdictional factor should be applied. PG&E contends that D.94-05-020 approved a joint settlement agreement that permitted the utilities to establish a number of interest-bearing subaccounts for expenditures and recoveries under HSM. PG&E also contends that our requirement to ratably amortize regulatory assets override these provisions.

In D.97-11-074, we stated:

We find that recovery of these uncertain future costs is not allowed under § 367: these may be generation-related regulatory assets, but the costs were not being collected in rates as of December 20, 1995. We will not allow any costs to be charged to the transition cost balancing account at this time. If environmental compliance costs are actually incurred and spent on generation-related projects, the utilities may request recovery in the annual transition cost proceedings. It is not reasonable to allow these sorts of speculative costs to add to the already large transition cost bill. This approach is consistent with our findings in D.97-08-056, in which we determined that as of January 1, 1998, allowing entries into PG&E's and Edison's Hazardous Substance Clean-up and Litigation Cost Accounts (also called HSM accounts) for additional generation-related costs would confer a competitive advantage on these utilities. (Id. at 157.)

Our determinations in D.97-12-039 does not grant regulatory asset recovery for those accounts which were specifically excluded from this treatment in D.97-11-074. The HSM, however, records costs that have already been incurred. PG&E's amortization of the generation portion of the HSM through the TCBA is correct.

Energy Division also removed costs associated with the amortization of Fossil/Geothermal decommissioning. PG&E believes that no adjustment is necessary; that the monthly decommissioning accrual is appropriately recorded. PG&E explains that there is an omission of the amortization of the environmental liability for the Hot Oil Pipeline as an independent line item, instead, it appears to be embedded in a catch-all line item to capture rounding and other differences. This leads to the recommended total adjustment of $356,227. We accept PG&E's explanation and will require no adjustment.

Energy Division also points out that PG&E has included interest and return on several of its regulatory assets and believes that this has not been authorized. PG&E contends that the Commission specifically authorized PG&E to earn interest and return on the QF Buyout Regulatory Asset, the Helms Adjustment Regulatory Asset, the Angels/Utica Regulatory Asset, and the Generation-Related Hazardous Substance Mechanism. As we determined above, we agree with Energy Division's findings.

In D.94-05-018, the Commission authorized the cost of capital as an appropriate discount rate for contract modifications that accelerate the schedule for payments to QFs. PG&E explains that it used a weighted rate of return of 9.26% for the 1994 and 1997 buyouts. This regulatory asset is comprised of accrual based costs that are present valued and paid out over a period of years. The liability for these costs is recorded on a present value basis, which means the actual amounts paid will exceed the regulatory asset balances. PG&E contends that it must earn interest to bring transition cost recovery up to the actual payment levels.

Similarly, PG&E explains that in D.96-06-061, the Commission authorized the use of 1996 authorized cost of capital as the interest rate used to calculate the amortization of the Angels/Utica regulatory asset. In D.96-0-037, the Commission adopted a Joint Settlement agreement that addressed the Helms Adjustment Account and provided that the 3-month commercial paper rate be applied to the amortization of this account. Finally, a similar joint settlement was approved for the HSM in D.94-05-020.

When the regulatory assets are recorded in the TCBA, those assets are transferred to an account for recovery. Interest and carrying costs should be recorded up to the point of transfer and then should cease to accrue. We cannot agree that it is reasonable to allow the utilities the opportunity to earn interest twice on these assets. The TCBA itself earns the three-month commercial paper rate; therefore, we will exclude the interest from continuing to accrue from the settlements. These modifications result from ensuring that our ratemaking under electric restructuring is fair, equitable, and reasonable.

Energy Division disputes the use of various jurisdictional factors as applied to its regulatory assets. PG&E explains that it does not apply jurisdictional factors to costs associated with the Angels/Utica Regulatory Asset, the Helms Adjustment Account, and the HSM, because the Commission authorized recovery of these costs only from customers within the Commission's jurisdiction. In the decisions cited above, the Commission authorized a certain dollar amount to be recovered from customers through rates within the Commission's jurisdiction; therefore, the authorized amount is the CPUC jurisdictional portion of the costs. We agree with PG&E. No jurisdictional factor should be applied.